Method and apparatus for adjustably treating a sour gas

ABSTRACT

A feed gas comprising CO 2 , H 2 S and H 2  is treated to produce an H 2 -enriched product and an H 2 S-lean, CO 2  product. The feed gas is separated to provide the H 2 -enriched product and a stream of sour gas. The stream of sour gas is divided into two parts, one of which is processed in an H 2 S removal system to form one or more streams of sweetened gas, and the other of which bypasses the H 2 S removal system, the stream(s) of sweetened gas and the sour gas bypassing the H 2 S removal system then being recombined to form the H 2 S-lean, CO 2  product gas. The division of the sour gas between being sent to and bypassing the H 2 S removal system is adjusted responsive to changes in the H 2 S content of the sour gas, so as to dampen or cancel the effects of said changes on the H 2 S content of the H 2 S-lean, CO 2  product gas.

CROSS-REFERENCE TO RELATED APPLICATIONS

This is a divisional of application Ser. No. 12/844,000 filed on Jul. 27, 2010 and now issued as U.S. Pat. No. 8,513,356, which is incorporated herein by reference in its entirety.

BACKGROUND OF THE INVENTION

The present invention relates to methods and apparatus for separating a feed gas, comprising carbon dioxide (CO₂), hydrogen sulfide (H₂S) and hydrogen (H₂), to form an H₂-enriched product gas and a sour gas depleted in H₂ and enriched in CO₂ and H₂S relative to the feed gas, and for adjustably treating said sour gas to produce an H₂S-lean, CO₂ product gas. The invention has particular application to the separation and treatment of sour syngas mixtures obtained from the gasification or reformation of carbonaceous feedstock.

The production of syngas via reforming or gasifying carbonaceous feedstock is well known. Where the feedstock contains sulfur, such as is often the case for solid (e.g. coal, petcoke) or heavy liquid (e.g. asphaltene) feedstocks for gasification, such processes result in an initial syngas stream containing hydrogen (H₂), carbon monoxide (CO), carbon dioxide (CO₂), hydrogen sulfide (H₂S) and, usually, other species such as methane (CH₄), carbonyl sulfide (COS) and carbon disulfide (CS₂). Commonly, the initial syngas mixture (crude syngas) is then subjected to further treatments. In particular, the initial syngas mixture may be subjected to a water-gas shift reaction, in which at least some of the CO present in the initial syngas mixture is converted to further CO₂ and H₂ by reaction with H₂O in the presence of a suitable shift catalyst. This process can also result in further H₂S being produced, via incidental conversion of other sulfur species (such as COS and CS₂) in the syngas during the water-gas shift reaction.

Due to concerns over greenhouse gas emissions, there is a growing desire to remove CO₂ from syngas prior to use of the remaining, H₂-enriched, product (comprising predominantly either H₂ or a mixture of H₂ and CO) as a combustion fuel or for chemicals production or refining applications. The CO₂ may be compressed, so as to be stored underground or used for enhanced oil recovery (EOR). H₂S may also have to be removed from the syngas. If the H₂-enriched product is to be used for chemicals production or refining then H₂S, if present, could be a poison for these downstream processes. Equally, if the H₂-enriched product is to be combusted in a gas turbine to generate power then H₂S, if present, will be converted into SO_(x) (SO₂ and SO₃), on which there are emission limits and which may, therefore, require removal from the combustion exhaust using expensive desulfurization technology. Equally, it may not be practical or permissible to store the H₂S with the CO₂. Therefore a solution must likewise be found for cost effective removal of H₂S from the CO₂ before pipeline transportation or geological storage.

The most commonly used commercial solution, currently, for capturing CO₂ and H₂S from sour syngas mixture uses a physical solvent (i.e. liquid solvent) absorption process, also referred to as an acid gas removal (AGR) process, such as Selexol™ or Rectisol®, to selectively separate H₂S, CO₂ and product H₂ into different streams. The H₂S-rich stream, typically containing about 20-80 mole % H₂S, is further treated to produce sulfur, usually by a Claus process coupled with a tail gas treating unit (TGTU). The CO₂ stream is typically compressed to meet pipeline or storage specifications, and the product H₂ is either sent as fuel to a gas turbine for power generation, or can be further processed via pressure swing adsorption (PSA) to achieve a ‘spec’ purity (typically 99.99 mole % or higher) for refining applications. However, a disadvantage of such AGR processes is that they are both costly and have significant power consumption.

As mentioned above, the typical method of removing the H₂S contained in the H₂S-rich stream obtained from the AGR process is via conversion to elemental sulfur using the Claus process. This process, as is well known, typically involves an initial thermal step followed by one or more catalytic steps. In the thermal step the H₂S-rich stream is reacted in a substoichiometric combustion at high temperatures to convert part of the H₂S to SO₂. The oxidant (i.e. O₂) to H₂S ratio during combustion is controlled so that in total one third of all H₂S is converted to SO₂. This provides the correct 2:1 molar ratio of H₂S to SO₂ for the subsequent catalytic steps. More specifically, in said subsequent catalytic steps, the 2:1 mixture of H₂S to SO₂ obtained from the thermal step is reacted over a suitable catalyst (e.g. activated aluminium(III) or titanium(IV) oxide) to convert the H₂S and SO₂ to elemental sulfur via the reaction 2H₂S+SO₂→⅜S₈+2H₂O. The Claus process ordinarily achieves high (e.g. 94 to 97%) but not complete levels of sulfur recovery and thus, as noted above, a TGTU is often also employed to recover and/or remove the remaining H₂S from the Claus process tailgas.

The Claus process is at its most economical when greater than 20 short tons per day (tpd) sulfur (about 18000 kg/day sulfur) is to be produced, and when the H₂S concentration in the feed to the process is greater than 10 mole %, and more preferably greater than 20 mole %. For production rates of less than 20 tpd (18000 kg/day) sulfur and/or for feed streams that are more dilute in H₂S concentration other, more economical, means of removing sulfur are generally preferred. Typically, these are catalyst-based processes that can be of the regenerable type or the ‘once-and-done’ scavenging type and require a varying degree of process complexity and operational cost depending on the processing conditions of the gas being treated. Typically, these processes are most suited for treating feeds with H₂S concentrations of less than 5%, and for processes where less than 20 tpd (18000 kg/day) is to be produced (although larger units have been designed and built). These processes are typically capable of removing 99% or more of the H₂S from the feed. Industry accepted examples of such H₂S disposition technologies include the LO-CAT and Stretford processes.

Specific examples of known prior art processes for separating H₂S, and/or other sulfur containing compounds, from a mixture include the following.

US-A1-2007/0178035, the disclosure of which is incorporated herein by reference, describes a method of treating a gaseous mixture comprising H₂, CO₂ and at least one combustible gas selected from the group consisting of H₂S, CO and CH₄. The gaseous mixture, which may be obtained from the partial oxidation or reforming of a carbonaceous feedstock, is separated, preferably by pressure swing adsorption (PSA), to produce a separated H₂ gas and a crude CO₂ gas comprising the combustible gas(es). The crude CO₂ gas is then combusted in the presence of O₂ to produce heat and a CO₂ product gas comprising the combustion product(s) of the combustible gas(es). The heat from at least a portion of the CO₂ product gas is recovered by indirect heat exchange with the separated H₂ gas or a gas derived therefrom. Where the combustible gas is, or includes, H₂S, the combustion products will include SO₂ and SO₃ (SO_(x)). In one embodiment, the SO_(x) is then removed by washing the CO₂ product gas with water to cool the gas and remove SO₃, and maintaining the cooled SO₃-free gas at elevated pressure in the presence of O₂, water and NO_(x) to convert SO₂ and NO_(x) to sulfuric acid and nitric acid, thereby obtaining an SO_(x)-free, NO_(x)-lean CO₂ gas.

The process described in this document therefore presents a sulfur disposition pathway in which the H₂S in the sour tailgas stream leaving the PSA is ultimately converted to sulfuric acid after being combusted to form SO_(x). This process presents a alternative to the conventional elemental sulfur disposition pathway and can, additionally, handle dilute H₂S concentrations as well as varying total amounts of sulfur. However, market conditions could limit the economic viability of such a sulfur disposition pathway, as the acid produced from such a process may be unsalable or of sufficiently poor quality that costly neutralization and disposal may be required.

U.S. Pat. No. 6,818,194 describes a process for removing H₂S from a sour gas, wherein the sour gas is fed to an absorber where the H₂S is removed from the gas by a nonaqueous sorbing liquor comprising an organic solvent for elemental sulfur, dissolved elemental sulfur, an organic base which drives the reaction between H₂S sorbed by the liquor and the dissolved sulfur to form a nonvolatile polysulfide which is soluble in the sorbing liquor, and a solubilizing agent which prevents the formation of polysulfide oil. The process further comprises adding SO₂ to the absorber to oxidize the polysulphide to elemental sulfur, thereby producing a more complete chemical conversion of H₂S by reducing the equilibrium back-pressure of H₂S. The sweet gas from the absorber exits the process, and the sorbent stream is then cooled and fed to a crystallizer to crystallize enough of the sulfur to balance the amount of H₂S previously absorbed.

In this process, the optimum molar ratio of H₂S to SO₂ in the feed stream to the absorber is the same as that for the catalytic stage of the Claus process, i.e. 2:1. In one embodiment, the process is applied to a feed stream which already contains a 2:1 mole ratio of H₂S to SO₂, such as where the feed stream is the tail gas of a Claus process which is operated so as to produce a tail gas with this composition. In another embodiment, the process may be applied to an H₂S containing feed stream to which SO₂ is first added, so as to obtain the desired 2:1 ratio prior to the stream being flowed through the absorber vessel. One exemplified way in which this may be achieved is to split the feed stream into two streams, pass one of said streams through a catalytic oxidation reactor to convert at least some of the H₂S contained therein to SO₂, and then recombine the streams.

U.S. Pat. No. 4,356,161 describes a process for reducing the total sulfur content of a high CO₂-content feed gas stream, comprising CO₂, H₂S and COS. The feed gas is first passed to an absorption column where it is contacted with an a regenerable, liquid polyalkanolamine absorbent selective for H₂S. The unabsorbed gas stream, comprising CO₂ and COS and substantially free of H₂S is then routed to a reduction step where it is combined with Claus off-gases and the COS reduced to H₂S. The treated gas is then passed to a second absorption column and the unabsorbed gas is vented to the atmosphere. The H₂S-rich solvent from both absorption columns is stripped in a common stripper and the H₂S-rich gas is passed to a Claus unit for conversion to elemental sulfur. The absorption process described in this document is commonly referred to in the industry as an ‘acid gas enrichment’ process.

U.S. Pat. No. 5,122,351 describes a refinement to the known LO-CAT and Stretford processes of removing H₂S by conversion to elemental sulfur, whereby the catalytic polyvalent metal redox solution used in said processes is recovered and re-used. This is achieved by interposing a closed loop evaporator/condenser process in the sulfur washing/filtering/recovery process so that wash water used to purify the sulfur and any polyvalent metal redox solution recovered from the sulfur melter are fed to an evaporator to concentrate the redox solution to a concentration capable of effective absorption of H₂S, and the water evaporated in the evaporator is condensed as pure water for use in washing and/or filtering the recovered sulfur.

US-A1-2010/0111824 describes a process for producing H₂ from a hydrocarbonaceous feed such as refinery residues, petroleum, natural gas, petroleum gas, petcoke or coal. In the exemplified embodiment, a crude syngas comprising H₂, CO, CO₂ and H₂S, is formed by gasifying residue oils, quenching the raw syngas, and subjecting the quenched syngas to a water-gas shift reaction. The syngas is separated via PSA into an H₂ product and a tail gas enriched in CO₂ and containing also H₂S, H₂ and CO. The PSA tail gas is mixed with a Claus process tail gas and the mixture supplied to a tail gas cleaning stage that uses a liquid solvent such as MDEA or Flexsorb SE® to selectively wash out H₂S from the gas mixture. H₂S is then liberated from the solvent and added to the feed stream to the Claus process.

U.S. Pat. No. 5,248,321 describes a process for removing sulfur oxides from gaseous mixtures such as flue gases from power plants, smelter gases, and other gases emitted from various industrial operations. The process involves contacting the gaseous mixture with a non-functionalized polymeric sorbent which is essentially hydrophobic, such as styrenic polymers, which sorbent may be employed in a PSA system to selectively adsorb SO₂. The SO₂ rich desorption stream may be fed to a Claus reactor along with a suitable amount of H₂S to produce elemental sulfur and water.

U.S. Pat. No. 7,306,651 describes the separation of a gas mixture comprising H₂S and H₂ using the combination of a PSA unit with a membrane. The PSA separates the feed stream into an H₂ stream and two H₂S-rich streams. One H₂S-rich stream is recovered as a waste stream and the second is compressed and put through a membrane to remove the H₂. The H₂S is then supplied to the PSA unit at pressure for rinsing and the H₂ returned to the PSA unit for purging. The gas mixture may, for example, be a stream obtained from a hydrodesulfurization process in a refinery. The H₂S-rich waste stream may be fed into one of the fuel/sour gas lines of the refinery.

EP-B1-0444987 describes the separation of CO₂ and H₂S from a syngas stream produced by gasification of coal. The syngas stream, containing H₂S, is reacted with steam in a catalytic CO-shift reactor to convert essentially all the CO in the stream to CO₂. The shifted stream is sent to a PSA unit that adsorbs CO₂ and H₂S in preference to H₂, to separate said stream into an H₂ product gas and a stream containing CO₂ and H₂S. The stream containing CO₂ and H₂S is sent to a second PSA unit that adsorbs H₂S in preference to CO₂, to provide a CO₂ product, stated to be of high purity, and a H₂S containing stream, the latter being sent to a Claus unit for conversion of the H₂S into elemental sulfur.

EP-A1-0633219 describes a process for removing sulfur compounds from a gas stream containing sulfur compounds, such as the off-gas from a Claus process. The process comprises the steps of: (a) converting the sulfur compounds to sulfuric acid, by combusting sulfur compounds other than SO₂ to form SO₂, and catalytically oxidizing SO₂ to SO₃, which then forms sulfuric acid in water; (b) separating the sulfuric acid from the gas stream; and (c) supplying the sulfuric acid into the thermal stage of a Claus process to allow the sulfuric acid to react with hydrogen sulfide to form elemental sulfur.

Similarly, U.S. Pat. No. 4,826,670 describes a process for improving an oxygen-enriched Claus process by introducing a sulfuric acid stream into the reaction furnace (thermal stage of the Claus process) to moderate oxygen-induced high temperatures which allow oxygen-enrichment and attendant throughput in the Claus process to higher levels.

Industries must strike a delicate balance when selecting technologies for processing sour feeds. A successful project must minimize capital and operating cost while ensuring the chosen technologies can appropriately and robustly meet ever tightening emissions standards. The final selection of H₂S disposition technology can, as discussed above, depend on the concentration at which the H₂S is present in the sour gas stream that is being treated. Where CO₂ is to be captured (either for underground storage or enhanced oil recovery), the presence of H₂S in the CO₂ product presents regulatory concerns and careful design measures must be in place to ensure product purity is upheld. This becomes an even more complex problem when one considers that the amount of H₂S in the sour gas stream can vary depending on feedstock variations, and variations in the process used to produce and/or separate out the sour gas. Significant variation in the amount of H₂S may, in turn, lead to the H₂S removal process becoming economically disadvantageous and/or to product purity and/or emission standards being compromised.

It is an object of embodiments of the present invention to provide methods and apparatus that allow for variations in the H₂S content of the sour gas while meeting air emissions standards and/or CO₂ purity specifications and achieving cost advantages over conventional technologies for sour gas processing.

It is an object of embodiments of the present invention to provide methods and apparatus that are capable of processing sour gas streams from varying feedstocks with varying compositions.

BRIEF SUMMARY OF THE INVENTION

According to the first aspect of the present invention, there is provided a method for treating a feed gas, comprising CO₂, H₂S and H₂, to produce an H₂-enriched product and an H₂S-lean, CO₂ product, the method comprising:

separating the feed gas to form a stream of H₂-enriched product gas and a stream of sour gas, the sour gas also comprising CO₂, H₂S and H₂ but being depleted in H₂ and enriched in H₂S and CO₂ relative to the feed gas;

dividing the stream of sour gas into two parts;

processing one part of said stream of sour gas in an H₂S removal system to form one or more streams of sweetened gas, depleted in H₂S and enriched in CO₂ relative to the feed gas;

bypassing the H₂S removal system with the other part of said stream of sour gas; and

combining said stream(s) of sweetened gas with said sour gas bypassing the H₂S removal system to form a stream of H₂S-lean, CO₂ product gas;

wherein the division of the sour gas between being sent to and processed in the H₂S removal system bypassing said system is adjusted responsive to changes in the H₂S content of the sour gas, such that the proportion of the sour gas processed in the H₂S removal system, as compared to bypassing said system, is increased if the H₂S content rises and decreased if the H₂S content drops.

According to a second aspect of the present invention, there is provided an apparatus for treating a feed gas, comprising CO₂, H₂S and H₂, to produce an H₂-enriched product gas and an H₂S-lean, CO₂ product gas, the apparatus comprising:

a pressure swing adsorption (PSA) system for separating the feed gas to form a stream of H₂-enriched product gas and a stream of sour gas, the sour gas comprising CO₂, H₂S and H₂ but being depleted in H₂ and enriched in H₂S and CO₂ relative to the feed gas;

an H₂S removal system for processing a part of the sour gas to form one or more streams of sweetened gas, depleted in H₂S and enriched in the CO₂ relative to the feed gas;

conduit means for transferring a part of said sour gas into the H₂S removal system and bypassing the H₂S removal system with another part of said sour gas;

a valve system for adjustably controlling the division of said sour gas between being sent to the H₂S removal system and bypassing said system; and

conduit means for withdrawing one or more streams of sweetened gas from the H₂S removal system and combining said stream(s) with the sour gas bypassing the H₂S removal system to form H₂S-lean, CO₂ product gas.

BRIEF DESCRIPTION OF SEVERAL VIEWS OF THE DRAWINGS

FIG. 1 is a flow sheet depicting an embodiment of the present invention;

FIG. 2 is a flow sheet depicting the operation of one type of H₂S removal system that may be used in the present invention; and

FIG. 3 is a flow sheet depicting the operation of an alternative type of H₂S removal system that may be used in the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The present invention provides a method and apparatus for treating a feed gas, comprising CO₂, H₂S and H₂, to produce an H₂-enriched product and an H₂S-lean, CO₂ product. The method comprises:

separating the feed gas to form a stream of H₂-enriched product gas and a stream of sour gas, the sour gas also comprising CO₂, H₂S and H₂ but being depleted in H₂ and enriched in H₂S and CO₂ relative to the feed gas;

dividing the stream of sour gas into two parts;

processing one part of said stream of sour gas in an H₂S removal system to form one or more streams of sweetened gas, depleted in H₂S and enriched in CO₂ relative to the feed gas;

bypassing the H₂S removal system with the other part of said stream of sour gas; and

combining said stream(s) of sweetened gas with said sour gas bypassing the H₂S removal system to form a stream of H₂S-lean, CO₂ product gas;

wherein the division of the sour gas between being sent to and processed in the H₂S removal system and bypassing said system is adjusted responsive to changes in the H₂S content of the sour gas, such that the proportion of the sour gas processed in the H₂S removal system, as compared to bypassing said system, is increased if the H₂S content rises and decreased if the H₂S content drops.

The method therefore addresses the problem of separating and treating, both economically and while still allowing for variations in composition (in particular, H₂S content), a sour gas as required to meet air emissions standards and/or CO₂ product purity specifications (e.g. for underground storage or EOR). This is achieved by bypassing the H₂S removal system with part of the sour gas so that only part of sour gas is treated in the H₂S removal system, and by adjusting the proportion of the sour gas treated in the H₂S removal system responsive to variations in the H₂S content of the sour gas (i.e. sending relatively more of the sour gas to the removal system and less to bypass when H₂S content rises, and relatively less of the sour gas to the removal system and more to bypass when H₂S content falls), so as to dampen or cancel the effect of said variations on the H₂S content of the H₂S-lean, CO₂ product. In this way, the H₂S content of the sour gas can still be reduced to a level necessary to meet air emissions standards and/or CO₂ product purity specifications during times of increased H₂S content, while at the same time avoiding an unnecessary or “excessive” degree of H₂S removal (and associated additional operating costs) when the H₂S content of the sour gas is lower. Thus, emissions standards and/or product purity specifications are maintained while at the same time achieving a cost advantage.

As noted above, variations in upstream processes which could cause the composition of the sour gas to change include, but are not limited to, changes in the feedstock (e.g. coal, petcoke, asphaltenes) from which (e.g. by gasification or reforming) the feed gas (e.g. sour syngas mixture) is obtained, mal-performance or deterioration in an upstream unit (e.g. gasifier/reformer, water-gas shift unit, pressure swing adsorber or other separation device), or other process upsets. Variations in H₂S content can be monitored using standard H₂S-analyzers, as will be known to one of ordinary skill in the art. H₂S content may be monitored at any suitable location. For example, the H₂S content of the sour gas stream may be monitored directly, by monitoring the content of this stream. Alternatively, it could be monitored indirectly, by monitoring the H₂S content of the feed gas and/or H₂S-lean CO₂ product stream.

The term “sour”, as used herein (and as is used in the art), refers to a gas or stream comprising H₂S. Likewise, the term “sweetened” or “sweet” refers to a gas or stream from which at least some of, and preferably substantially all or all of the H₂S has been removed.

The feed gas comprises, as noted above, at least CO₂, H₂S and H₂. The feed gas preferably comprises from about 10 to about 65 mole % CO₂, more preferably from about 10 to about 45 mole % CO₂. The feed gas preferably comprises up to about 3 mole %, or up to about 1.5 mole % H₂S, and preferably comprises at least about 50 ppm H₂S. The feed gas preferably comprises at least about 30 mole %, and more preferably at least about 50 mole % H₂. The feed gas is preferably a gaseous mixture obtained from gasification or reformation of a carbonaceous feedstock, and which may have been subjected to further processes such as, for example, a water-gas shift reaction (to convert some or all of the CO, present in the initially produced crude syngas, to CO₂ and H₂). Preferably, the feed gas is a sour syngas mixture (which, therefore, contains also at least some CO in addition to said CO₂, H₂S and H₂). The feed gas may, for example, also contain: other carbonaceous species, such as CH₄; other sulfurous (i.e. sulfur containing) species, such as COS and CS₂; inerts, such as Ar and/or N₂; and/or water.

Where the feed gas contains also other sulfurous species (in addition to H₂S), it is preferred that these are dealt with in the method of the present invention in the same manner as H₂S. Thus, where for example a stream is indicated herein as being enriched in, depleted in, lean in or free of H₂S, said stream is preferably enriched in, depleted in, lean in or free of all other sulfurous species (where present) also; and where reference is made herein to H₂S being adsorbed, removed or combusted then preferably other sulfurous species (where present) are adsorbed, removed or combusted also. In addition, where reference is made herein to maximum ppm or mole % of H₂S, preferably these represent also the maximum ppm or mole % of all sulfurous species (in total) in the gas or stream in question. Thus, for example, where the feed gas contains also other sulfurous species, the feed gas preferably comprises at most about 3 mole %, and more preferably at most about 1.5 mole % of sulfurous species (in total).

The H₂-enriched product gas is enriched in H₂ relative to the feed gas (i.e. it has a higher mole % of H₂ than the feed gas). It is also depleted in H₂S and CO₂ relative to the feed gas (i.e. it has a lower mole % of H₂S and a lower mole % of CO₂ than the feed gas). It is preferably free or at least substantially free of H₂S. For example, the H₂-enriched product gas preferably has an H₂S concentration of less than about 20 ppm, more preferably less than about 10 ppm, and most preferably less than about 5 ppm. It may also be free or at least substantially free of CO₂. Where the feed gas contains also CO, the H₂-enriched product gas may be enriched in CO or depleted in CO (or, indeed, neither) relative to the feed gas, depending on the desired end use of said product. It is generally preferred, however, that where the feed stream contains more than minor amounts of CO then the H₂-enriched product gas is enriched in CO as well as H₂. Thus, it is generally preferred that it is only where the feed gas has a CO concentration of about 5 mole % or less, more preferably of about 2 mole % or less, and most preferably of about 1 mole % or less that the H₂-enriched product gas is not enriched in CO relative to the feed gas.

Preferably, the H₂ recovery in the H₂-enriched product gas (i.e. the percentage of the H₂ present in the feed gas that is recovered in the H₂-enriched product) is at least about 80%, more preferably at least about 85%, more preferably at least about 90%, and most preferably at least about 95%. Where the feed stream contains CO and it is desired that the H₂-enriched product is enriched in CO as well as H₂, the combined recovery of H₂ and CO in the H₂-enriched product (i.e. the percentage of H₂ and CO (in combination) present in the feed gas that is recovered in the H₂-enriched product) is preferably at least about 75%, more preferably at least about 80%, and most preferably at least about 90%. The percentage recovery in the H₂-enriched product gas of a component or combination of components can be calculated from the moles of the component or components in question in the feed gas and H₂-enriched product gas. Thus, if for example the feed gas were to contain 25 kmol/hr of H₂ and 25 kmol/hr of CO, and the H₂-enriched product gas were to comprise 23 kmol/hr of H₂ and 20 kmol/hr of CO, in this case 92% of the H₂ would be recovered in the H₂-enriched product stream and 86% of the H₂ and CO (in combination) would be recovered in the H₂-enriched product stream.

Preferably, the H₂-enriched product gas comprises at least about 90 mole H₂ or a mixture of H₂ and CO, and is free or at least substantially free of H₂S. The H₂-enriched product gas may, for example, comprise greater than about 90 mole % H₂S as may be the case where the H₂-enriched gas is intended for use as a fuel for combustion and expansion in, for example, a gas turbine to generate power. Alternatively, the H₂-enriched gas may, for example, comprise greater than about 99.99 mole % H₂, as for example may be the case where the H₂-enriched gas is intended for use, without requiring further purification, for chemicals or refining applications. Alternatively still, the H₂-enriched gas may, for example, comprise at least about 90 mole %, and more preferably 95 mole % of a mixture of H₂ and CO, with a CO:H₂ ratio as desired for the product's intended application, such as a CO:H₂ ratio between about 1:3 and about 3:1, and more preferably from about 1:1 to about 1:2.5 (as, for example, may be desired in Fischer-Tropsch process).

The sour gas comprises, as noted above, CO₂, H₂S and at least some H₂, although it is depleted in H₂ and enriched in H₂S and CO₂ relative to the feed gas (i.e. has a lower mole % of H₂ and higher mole % of H₂S and CO₂ than the feed gas). Preferably, the sour gas contains at most about 30 mole % H₂, and typically will contain at least about 5 mole % H₂. Preferably, the sour gas comprises at most about 6 mole %, and more preferably at most about 3 mole % or at most about 1 mole % H₂S, and preferably the sour gas comprises at least about 100 ppm and more preferably at least about 0.5 mole % H₂S. Preferably, the sour gas comprises at least about 80 mole CO₂. The sour gas may further comprise other carbonaceous species, such as CO and/or CH₄, and/or other sulfur containing species, such as COS and/or CS₂, as may have been present in the feed gas. Where CO and/or CH₄ are present in sour gas stream, the stream preferably comprises at most about 15 mole % of CO, CH₄ or the combination of the two.

The or each stream of sweetened gas, obtained from processing the sour gas in the H₂S removal system to remove H₂S therefrom, is as noted above depleted in H₂S relative to the feed gas. As with the sour gas from which it or they are formed, the or each stream of sweetened gas is also enriched in CO₂, and depleted in H₂, relative to the feed gas. Preferably, the or each stream of sweetened gas free or substantially free of H₂S. Preferably, the H₂S removal system removes at least about 90%, more preferably at least about 97%, and most preferably at least about 99% of the H₂S present in the sour gas being processed in said system, such that the percentage of the H₂S present in the sour gas that is recovered in the stream of sweetened gas or, where more than one stream is produced, in the streams in combination is preferably at most about 10%, more preferably at most about 3%, more preferably at most about 1% (the percentage recovery of H₂S likewise being calculable from the moles of H₂S present in the sour gas to be processed versus the moles of H₂S present in the stream or combination of streams of sweetened gas). The stream of sour gas bypassing the H₂S removal system is, self-evidently, not processed to remove H₂S therefrom.

The H₂S-lean, CO₂ product gas preferably has an H₂S concentration of at most about 200 ppm, more preferably at most about 100 ppm. Preferably, the H₂S-lean, CO₂ product gas has an H₂ concentration of at most about 4 mole %, more preferably at most about 1 mole %.

The feed gas is, in preferred embodiments, separated to form the stream of H₂-enriched product gas and stream of sour gas by pressure swing adsorption (PSA). The use of pressure swing adsorption to separate out the H₂-enriched product provides for both capital and operating cost savings and reduced power consumption as compared to use of liquid solvent absorption processes as used in the standard commercial arrangement (whereby, as described above, a liquid solvent absorption process is used to separate a feed into separate H₂S, CO₂ and H₂ streams, followed by treatment of the H₂S-rich stream in a Claus unit).

The PSA system in which the separation is carried out will comprise one or more types of adsorbent that selectively adsorb CO₂ and H₂S (i.e. that adsorb CO₂ and H₂S preferentially to H₂). If other sulfur containing species, such as COS and/or CS₂, are present in the feed gas then a PSA system is used which, preferably, comprises one or more types of adsorbent that selectively adsorb these additional sulfur containing species also. If CO and/or other carbon containing species are also present in the feed gas, then adsorbents that selectively adsorb some or all of these species may or may not be used, depending on the desired composition of the H₂-enriched product gas. Exemplary adsorbents include carbons, aluminas, silica gels and molecular sieves. For example, a single layer of silica gel may be used if the product requirement is a H₂/CO mixture, a single layer of silica gel or a silica gel/carbon split may be used if the required product is gas turbine grade H₂, and a silica gel/carbon/5A zeolite split may be used if the required product is high purity H₂. A suitable type of silica gel for use as an adsorbent is, for example, the high purity silica gel (greater than 99% SiO₂) described in US-A1-2010/0011955, the disclosure of which is incorporated herein by reference.

The system may comprise a plurality of adsorbent beds, as is known in the art. For example, the system may comprise a plurality of beds, with the PSA cycles of the individual beds being appropriately staggered so that at any point in time there is always at least one bed undergoing adsorption and at least one bed undergoing regeneration, such that the system can continuously separate the stream fed to it. The system may comprise beds arranged in series and/or in parallel. The PSA system may comprise a single type of adsorbent, selective for all the components that are to be selectively adsorbed by said system, or more than one type of adsorbent which adsorbents in combination provide the desired selective adsorption. Where more than one type of adsorbent is present, these may be intermixed and/or arranged in separate layers/zones of a bed, or present in separate beds arranged in series, or arranged in any other manner as appropriate and known in the art.

The PSA system may be operated in the same way as known PSA systems for separating H₂ from CO₂ (also referred to herein as H₂—PSA systems), with all known cycle options appropriate to this technology area (e.g. cycle and step timings; use, order and operation of adsorption, equalization, repressurisation, depressurization and purge steps; and so forth). The PSA cycle will, of course, typically include at least adsorption, blowdown/depressurisation and purge steps. During the adsorption step the feed gas is fed at super-atmospheric pressure to the bed(s) undergoing the adsorption step and CO₂, H₂S and any other species for which the adsorbent is selective are selectively adsorbed, at least a portion of the gas pushed through the bed(s) during this step forming all or at least a portion of the stream of H₂-enriched product gas. During the blowdown/depressurization and purge steps the pressure in the bed(s) is reduced and a purge gas passed through the bed(s) to desorb CO₂, H₂S and any other species adsorbed in the previous adsorption step, thereby regenerating the bed(s) in preparation for the next adsorption step, at least a portion of the gases obtained from the blowdown and/or purge steps forming all or at least a portion of the stream of sour gas. Although, as noted above, the adsorbent used in the PSA system is selective for CO₂ and H₂S, due to the manner in which the PSA process operates some H₂ will nevertheless also be present in the sour gas (for example as a result of some H₂ also being adsorbed, being present in the void space of the bed(s), and/or being present in the gas(es) used to purge the bed(s)).

Suitable operating conditions for PSA systems are likewise known in the art. The adsorption step may, for example, be carried out by feeding the feed gas to the PSA system at a pressure of about 1-10 MPa (10-100 bar) absolute and at a temperature in the range of about 10-60° C., in which case the H₂-enriched product gas will be obtained at about the same pressure. The H₂-enriched product gas may, if desired, be expanded to produce power prior to said product gas being put to further use (e.g. in chemicals or refining applications).

The sour gas will typically be obtained at pressures about or slightly above atmospheric, i.e. about or slightly above 0.1 MPa (1 bar) absolute, but may for example also be obtained at pressures of up to about 0.5 MPa (5 bar) absolute or at sub-atmospheric pressures of down to about 0.01 MPa (0.1 bar) absolute (in this latter case the PSA system being a vacuum pressure swing adsorption system). Higher pressures for the blowdown and purge steps may also be employed if desired (although the performance of the PSA system will decrease where the base pressure of the PSA is higher, due to the dynamic capacity of the PSA system being decreased, the gas obtained from the blowdown and purge steps will be obtained at higher pressure, which may be beneficial where compression of these gases for further use is required). The gas used for purging can be preheated at least in part before use. If heating is used, then a typical temperature that the purge gas is raised to is in the range of about 150° C. to about 300° C.

In a preferred embodiment, the method is carried out using a fossil fuel fired gasification system integrated with a PSA system that separates the sour syngas stream produced by the gasifier (optionally after further process steps such as a water-gas shift reaction) to form the stream of H₂-enriched product gas and stream of sour gas.

The method may further comprise separating the stream of H₂S-lean, CO₂ product gas to form an H₂S-lean, H₂-lean, CO₂ product and a gas comprising H₂. Typically, the gas comprising H₂ is enriched in H₂ relative to the feed gas, and therefore constitutes a second H₂-enriched gas (the H₂-enriched product gas being the “first” H₂-enriched gas). Preferably, the H₂S-lean, H₂-lean, CO₂ product comprises at least about 98 mole %, more preferably at least about 99 mole %, more preferably at least about 99.9 mole % CO₂. Preferably, the gas comprising H₂ (second H₂-enriched gas) is at least about 60 mole %, more preferably at least about 70 mole % H₂. The gas comprising H₂ (second H₂-enriched gas) may be used in any other process where it would be of value. For example, depending on its composition the gas could be: blended with the H₂-enriched product gas (i.e. the “first” H₂-enriched gas) obtained via separation of the feed gas; recycled back to the system used to separate the feed gas (for example, where said system is a PSA system the gas comprising H₂ may be combined with the feed gas, separated in an additional adsorption step to provide a further portion of the H₂-enriched product gas and sour gas, used as a rinse gas in a rinse step of the PSA cycle, or used as a repressurisation gas in a repressurisation step of the PSA cycle); and/or used in one or more additional processes. The H₂S-lean, H₂-lean, CO₂ product may be compressed (or pumped) to sufficient pressure for sequestration or for use in EOR applications.

The H₂S-lean, CO₂ product gas may, for example, be separated to form the H₂S-lean, H₂-lean, CO₂ product and gas comprising H₂ (second H₂-enriched gas) by partial condensation or using membrane separation.

In the case of partial condensation, the H₂S-lean, CO₂ product gas is cooled and separated into a condensate and a vapour, for example using one or more phase separators and/or distillation columns. The heavier components, namely CO₂ and remaining H₂S, are concentrated in the liquid phase, which therefore forms the H₂S-lean, H₂-lean, CO₂ product, the gaseous phase forming the gas comprising H₂ (second H₂-enriched gas). Partial condensation systems that would be suitable for separating the H₂S-lean, CO₂ product gas are, for example, described in US-A1-2008/0173585 and US-A1-2008/0173584, the disclosures of which are incorporated herein by reference.

Where partial condensation is used, it is also important that water and other components that may freeze out (e.g. NH₃ and trace levels of tars) are not present in the stream of H₂S-lean, CO₂ product gas introduced into partial condensation system or are present only in sufficiently small amounts to avoid them freezing out and blocking the condensation system heat exchanger (which is used to cool the gas as necessary for subsequent separation into condensate and vapour) or otherwise affecting the performance of the condensation system. In order to remove water a drying system, such as a temperature swing adsorption (TSA) or absorptive (e.g. gycol, glycerol) system, may be used at any point upstream of the condensation system.

Where membrane separation is used, the H₂S-lean, CO₂ product gas may be separated using one or more membranes having selective permeability (i.e. that are more permeable to one or more components of the stream to be separated than they are to one or more other components of said stream). For example, membranes may be used that are permeable to H₂ but largely impermeable to CO₂ and/or vice versa, such as are described in Journal of Membrane Science 327 (2009) 18-31, “Polymeric membranes for the hydrogen economy: Contemporary approaches and prospects for the future”, the disclosure of which is incorporated herein by reference. Where, for example, a membrane is used that is permeable to H₂ but is, in comparison, largely impermeable to CO₂ and H₂S, during the membrane separation process the H₂S-lean, CO₂ product gas is introduced (typically at elevated pressure) into the membrane separation system and separated by the membrane into the second H₂-enriched gas (obtained at a lower pressure from the permeate side of the membrane) and the H₂S-lean, H₂-lean, CO₂ product (obtained at elevated pressure from the upstream side of the membrane). A nitrogen ‘sweep’ stream may also be used to increase the driving force for separation, allowing the stream of H₂-enriched gas leaving the membrane separation system to be obtained at a higher pressure for the same membrane surface area. Membrane separation technologies are well documented in the literature and can be broadly classified as metallic, inorganics, porous carbons, organic polymers, and hybrids or composites (see, for example, Membranes for Hydrogen Separation, Nathan W. Ockwig and, Tina M. Nenoff, Chemical Reviews 2007 107 (10), 4078-4110, the disclosure of which is incorporated herein by reference). Polymer membranes constitute a preferred type of membrane for use in the present invention.

The H₂S removal system may be a system of any type suitable for processing the sour gas to obtain the desired stream(s) of sweetened gas, and may comprise a single type of system or a combination of two or more different types of systems.

In one embodiment, the H₂S removal system may, for example, comprise an adsorption system comprising one or more beds of adsorbent selective for H₂S, the processing of sour gas in the H₂S removal system comprising passing sour gas through said beds of adsorbent to adsorb H₂S therefrom and form said or one of said stream(s) of sweetened gas.

The bed or beds may comprise a single type of adsorbent or more than one type of adsorbent selective for H₂S (i.e. that adsorb H₂S in preference to CO₂). Preferably the system also comprises one or more adsorbents selective for any other sulfur containing species present in the sour gas (which adsorbents may be the same or different from the adsorbent(s) selective for H₂S, and may be present in the same or different beds of the system). The system may, for example, use adsorbent of a non-regenerable type, e.g. H₂S scavengers such as iron sponge or ZnO, which are disposed of and replaced once saturated with H₂S (although, in cases where the sour gas comprises greater than about 100 ppm H₂S any non-regenerable adsorbents are preferably only used as a final polishing step of the H₂S removal process, the H₂S removal system therefore including also a regenerable adsorbent system or another type of H₂S removal system that first removes the bulk of the H₂S prior to removal of remaining H₂S by the non-regenerable adsorbent). Use of method of the present invention in connection with such a system can reduce capital/operating costs by reducing the flow rate of sour gas that the bed(s) of regenerable adsorbent have to process and/or frequency with which the H₂S scavenger has to be replaced.

In one embodiment, the H₂S removal system may, for example, comprise a system that converts H₂S to elemental sulfur, the processing of sour gas in the H₂S removal system comprising contacting sour gas with a reagent (e.g. one or more catalysts and/or reactants) to convert H₂S to elemental sulfur (which sulfur may then be removed by, for example, any suitable sulfur handling processes as are known in the art) and form said or one of said stream(s) of sweetened gas. Preferably, the H₂S removal system comprises a catalyst that catalyses the conversion of H₂S to elemental sulfur.

The system for converting H₂S to elemental sulfur may, for example, be a system that converts the H₂S to elemental sulfur by a direct oxidation or redox process (i.e., LO-CAT, Sulfa-Treat). These processes are well known in the industry and usually operate in three sections comprising a gas treating, a catalyst regeneration section, and a sulfur handling section. Use of such systems may be a preferred option where the sour gas stream typically comprises less than about 5%. Use of method of the present invention in connection with such a system can reduce costs by reducing operating costs associated with regenerating the catalyst (in the catalyst regeneration section), and also reducing the amount of sulfur that is removed thus reducing operating costs associated with the sulfur handling section.

Where the sour gas contains, in addition to H₂S, one or more other sulfur containing species, the method may further comprise treating a portion or all of the sour gas to be processed in the H₂S to elemental sulfur conversion system to convert one or more of said sulfur containing species to H₂S prior to said sour gas being processed in said conversion system. This may, in particular, be preferred where a higher H₂S concentration is desirable for optimal performance of the conversion system in question. Alternatively or additionally, one or more other H₂S and/or sulfur species containing gas streams, as may be available on-site or be imported from off-site, may be blended with the sour gas to be processed in the conversion system, again to increase the overall H₂S concentration of said gas to be processed in the conversion system, where this may be desirable.

Other sulfur species that may be present in the sour gas include, in particular, and as described above, COS and CS₂. A variety of processes for converting such species to H₂S are known, and may suitably be employed. For example, COS may be converted to H₂S and CO₂ in the presence of alumina and/or titania catalysts via the hydrolysis reaction COS+H₂O→H₂S+CO₂. CS₂ may be reduced to produce H₂S via the reaction CS₂+2H₂→2H₂S+C, which is generally favored at high temperatures and can proceed over a Co—Mo—Al catalyst. The aforementioned hydrolysis reaction is also favored at high temperatures.

In one embodiment, the H₂S removal system may, for example, comprise a combustion system, wherein the processing of sour gas in the H₂S removal system comprises combusting sour gas in the presence of O₂ to produce heat and a combustion effluent depleted in H₂S and H₂, relative to the feed gas, and comprising CO₂, SO_(x) and H₂O, SO_(x) being removed from said combustion effluent to form (from the resulting SO_(x)-depleted combustion effluent) said or one of said stream(s) of sweetened gas. Use of method of the present invention in connection with such a system can reduce costs by reducing operating cost associated with the addition of a trim fuel (i.e. natural gas) which may necessarily or desirably be combusted alongside the sour gas to support combustion of the latter (in particular, where the latter is of low calorific value). The bypassing of the combustion system with part of the sour gas also allows for potential further recovery of hydrogen still present in that part of the sour gas (all or substantially all of the hydrogen sent to the combustion system typically being combusted to form water) which may likewise be of economic benefit.

The combustion system is preferably an oxy-fuel combustion system, whereby the sour gas is combusted via oxy-fuel combustion. As used herein, the term “oxy-fuel combustion” refers to combustion where the oxidant stream, that is mixed with the sour gas (constituting the fuel to be combusted) to provide the O₂ for combustion, comprises greater than 21 mole % oxygen. More preferably, the oxidant stream is at least about 90 mole % oxygen, and most preferably at least about 95 mole % oxygen. The oxidant stream may be oxygen enriched air, oxygen enriched recycled flue gas, or substantially pure or pure oxygen. Preferably all or at least substantially all of the H₂S, H₂ and any other combustible components present in the sour gas are combusted to form their combustion products (SO_(x) and H₂O in the case of H₂S, and H₂O in the case of H₂). Preferably, therefore, the amount of O₂ provided by the oxidant stream is in excess of the stoichiometric amount theoretically required for complete combustion of all combustible components present in the sour gas to be combusted.

In this embodiment, the method preferably further comprises passing the combustion effluent through a heat exchanger to recover heat therefrom via indirect heat exchange. The recovered heat may be put to various uses. For example, the recovered heat may be used to generate steam (which may, for example, be used in turn in a steam turbine to generate power), supplied to other processes, and/or exchanged with other process streams.

Preferably, SO_(x) is removed from said combustion effluent by cooling the combustion effluent to condense out water and convert SO₃ to sulfuric acid (typically, this will be carried out in a heat exchanger separate from any heat exchanger initially used to recover useful heat from the combustion effluent in the manner discussed above), and maintaining the cooled combustion effluent at elevated pressure(s), in the presence of O₂, water and optionally NO_(x), for a sufficient time to convert SO₂ to sulfurous acid and/or SO₂ to sulfuric acid and NO_(x) to nitric acid.

This process by which SO_(x) is removed may, in particular, be a process as described in US-A1-2007/0178035, preferred features of this process being, therefore, as described in this document. In particular, at least substantially all (and usually all) of the SO_(x) and the bulk, usually about 90%, of any NO_(x) is preferably removed. The combustion effluent is usually produced at a pressure of from about 0.1 MPa (1 bar) to about 0.7 MPa (7 bar), and more typically from about 0.1 MPa (1 bar) to about 0.2 MPa (2 bar), depending at least in part on the pressure at which the sour gas stream is introduced into the combustion system, and may be compressed to the elevated pressure. The elevated pressure is usually at least about 0.3 MPa (3 bar) and preferably from about 1 MPa (10 bar) to about 5 MPa (50 bar). Contact time (or “hold-up”) between the gaseous components and the liquid water after elevation of the pressure affects the degree of conversion of SO₂ to H₂SO₄ and NO_(x) to HNO₃, a total “hold-up” time of no more than 60 seconds usually being sufficient for maximum conversion of SO₂/NO_(x). Counter current gas/liquid contact devices such as columns or scrub towers allow intimate mixing of water with the gaseous components for continuous removal of SO₂ and NO_(x), and thus constitute suitable devices for providing the required contact time for the conversion(s). The O₂ required for the conversions may be added although an amount of O₂ may be present in the combustion effluent, for example where a stoichiometric excess of O₂ was used during combustion. Water is present in the combustion effluent as one of the combustion products, but further water may be added if required. Likewise, NO_(x) may already be present in the combustion effluent, and/or may be added as required.

In one embodiment, the H₂S removal system may, for example, comprise both a combustion system and a system that converts H₂S to elemental sulfur via reaction with SO₂, sulfuric acid and/or sulfurous acid. The sour gas to be processed in the H₂S removal system is, in this case, divided into two streams, and said processing comprises:

contacting, in the H₂S to elemental sulfur system, a stream of sour gas with the SO₂, sulfuric acid and/or sulfurous acid to convert H₂S to elemental sulfur (which sulfur may then be removed by, for example, any suitable sulfur handling processes as are known in the art) and form said stream or one of said stream(s) of sweetened gas; and

combusting, in the combustion system, another stream of sour gas in the presence of O₂ to produce heat and a combustion effluent depleted in H₂S and H₂, relative to the feed gas, and comprising CO₂, SO_(x) and H₂O, and: (i) introducing at least a portion of the combustion effluent, or an SO₂-enriched stream separated from the combustion effluent, into the H₂S to elemental sulfur conversion system to provide at least a portion of said SO₂ for the reaction with H₂S; and/or (ii) converting SO_(x) in the combustion effluent to sulfuric and/or sulfurous acid, and introducing at least a portion of said acid into the H₂S to elemental sulfur conversion system to provide at least a portion of said acid for the reaction with H₂S.

The method according to this embodiment therefore has the further advantage, over the method described in US-A1-2007/0178035, that at least a portion of the SO_(x) formed from combustion of H₂S in the combustion system is disposed of either by conversion into elemental sulfur rather than by conversion to sulfuric acid, or by at least a portion of the sulfuric and/or sulfurous acid that is formed from the SO_(x) being further converted to elemental sulfur.

As described above in connection with other embodiments where the H₂S removal system comprises an H₂S to elemental sulfur conversion system, where the sour gas contains in addition to H₂S one or more other sulfur containing species the method may further comprise treating a portion or all of said stream of sour gas to be processed in said conversion system to convert one or more of said sulfur containing species to H₂S prior to said stream being processed in the conversion system. Alternatively or additionally, one or more other H₂S and/or sulfur species containing gas streams, as may be available on-site or be imported from off-site, may be blended with the sour gas stream to be processed in the conversion system, again to increase the overall H₂S concentration of said gas to be processed in the conversion system.

As described above, in connection with other embodiments where the H₂S removal system comprises a combustion system, the combustion system may preferably be an oxy-fuel combustion system, whereby the sour gas is combusted via oxy-fuel combustion. The method may preferably further comprise passing the combustion effluent through a heat exchanger to recover heat therefrom via indirect heat exchange. The recovered heat may be used to generate steam, supplied to other processes, and/or exchanged with other process streams. The recovered heat may, for example, be used to supply some or all of the thermal load that may be necessary for optimal conversion of H₂S in the H₂S to elemental sulfur conversion system and/or for optimal prior treatment of the sour gas feed to said conversion system to convert additional sulfur species to H₂S (where such prior treatment takes place).

Where the H₂S to elemental sulfur system converts H₂S to elemental sulfur via reaction with SO₂, and a portion of the combustion effluent is introduced into said conversion system to provide at least a portion of said SO₂ for reaction with H₂S, the combustion effluent may be divided into at least two thereof, one of which is introduced into the conversion system to provide at least a portion of said SO₂ for the reaction with H₂S, and the other of which forms a second of said streams of sweetened gas.

Where the H₂S to elemental sulfur system converts H₂S to elemental sulfur via reaction with SO₂, the combustion effluent is separated to form an SO₂-enriched stream (i.e. stream enriched in SO₂ relative to the combustion effluent) and an SO₂-depleted stream (i.e. a stream depleted in SO₂ relative to the combustion effluent), and the SO₂-enriched stream is introduced into said conversion system to provide at least a portion of said SO₂ for reaction with H₂S, the SO₂-depleted stream may form a second of said streams of sweetened gas. The combustion effluent may be separated to form an SO₂-enriched stream and an SO₂-depleted stream via any suitable means. For example, the combustion effluent may be separated using suitable adsorbents (such as for example described in U.S. Pat. No. 5,248,321, the disclosure of which is incorporated herein by reference) or via distillation (for example using a system as described in EP-A-0798032, the disclosure of which is incorporated herein by reference).

By introducing into the H₂S to elemental sulfur conversion system a separated SO₂-enriched stream, or only that amount of the combustion effluent required to provide the necessary amount of SO₂ for reaction with H₂S, and taking the SO₂-depleted stream or the remainder of the combustion effluent as an additional stream of sweetened gas, the amount of sour gas to be combusted in the combustion system relative to the amount treated in the conversion system can be increased without affecting the reaction stoichiometry in the conversion system. This, in turn, may allow additional useful heat to be generated by and recovered from the combustion reaction. However, in this case care should be taken to ensure that the amount of combustion effluent, or amount of any residual SO_(x) in the SO₂-depleted stream, taken as an additional stream of sweetened gas is not such that the SO_(x) content of the H₂S-lean, CO₂ product gas exceeds acceptable limits. Where, for example, the combustion effluent is being divided and a portion thereof taken as an additional stream of sweetened gas, it is therefore preferable that both the division of sour gas between the stream sent to the conversion system and the stream sent to the combustion system, and the division of the combustion effluent between being sent to the conversion system and being taken as an additional sweetened gas, are adjusted as necessary responsive to changes in the H₂S content of the sour gas, such that both the reaction stoichiometry within the conversion system and the SO_(x) content of the H₂S-lean, CO₂ product gas are maintained within desired limits.

Where the H₂S to elemental sulfur system converts H₂S to elemental sulfur via reaction with SO₂, the H₂S to elemental sulfur system preferably comprises a catalyst that catalyses the conversion of H₂S to elemental sulfur via reaction with SO₂. Suitable catalysts include, for example, catalysts as used in the catalytic step(s) of the Claus process.

Where the H₂S to elemental sulfur conversion system converts H₂S to elemental sulfur via reaction with sulfuric and/or sulfurous acid, SO_(x) in the combustion effluent is converted to sulfuric and/or sulfurous acid, and at least a portion of said acid is introduced into the H₂S to elemental sulfur conversion system to provide at least a portion of said acid for the reaction with H₂S, the SO_(x)-depleted combustion effluent (obtained following removal of the acid) may form a second of said streams of sweetened gas. Prior to being introduced in the H₂S to elemental sulfur conversion system, the sulfuric and/or sulfurous acid stream may be heated to drive off excess water, thereby concentrating the acid before it is added to the conversion system. Such evaporation of water is preferably carried out at atmospheric pressure or under vacuum.

The SO_(x) in the combustion effluent may be converted to sulfuric acid or sulfuric and sulfurous acid by cooling the combustion effluent to condense out water and convert SO₃ to sulfuric acid, and maintaining the cooled combustion effluent at elevated pressure(s), in the presence of O₂, water and optionally NO_(x), for a sufficient time to convert SO₂ to sulfurous acid and/or SO₂ to sulfuric acid and NO_(x) to nitric acid. The process by which SO_(x) is converted to sulfuric acid may, in particular, be a process as described in US-A1-2007/0178035, preferred features of this process being, therefore, as described in this document and/or as described above in relation to other embodiments of the present invention where SO_(x) in the combustion effluent is converted to sulfuric acid.

The conversion of H₂S to elemental sulfur via reaction with sulfuric acid may proceed according to the reaction 3H₂S+H₂SO₄→4S+4H₂O, wherein aqueous H₂SO₄ is reacted with gaseous H₂S. Similarly, the conversion of H₂S to elemental sulfur via reaction with sulfurous acid may proceed according to the reaction 2H₂S+H₂SO₃→3S+3H₂O, wherein aqueous H₂SO₃ is reacted with gaseous H₂S. Further details regarding the reaction between H₂S and sulfuric acid are, for example, given in: Reactions between Hydrogen Sulfide and Sulfuric Acid: A Novel Process for Sulfur Removal and Recovery, Qinglin Zhang, Ivo G. Dalla Lana, Karl T. Chuang,^(†) and, Hui Wang, Industrial & Engineering Chemistry Research 2000 39 (7), 2505-2509; Kinetics of Reaction between Hydrogen Sulfide and Sulfur Dioxide in Sulfuric Acid Solutions, Ind. Eng. Chem. Res. 2002, 41, 4707-4713; Thermodynamics and Stoichiometry of Reactions between Hydrogen Sulfide and Concentration Sulfuric Acid, The Canadian Journal of Chemical Engineering, Volume 81, February 2003; and Mass-Transfer Characteristics for Gas-Liquid Reaction of H₂S and Sulfuric Acid in a Packed Column Ind. Eng. Chem. Res. 2004, 43, 5846-5853; the disclosures of which are incorporated herein by reference.

In any of the above embodiments, the method may further comprise processing one or more additional H₂S containing streams in the H₂S removal system alongside said part of said stream of sour gas to be processed in the H₂S removal system. These additional streams may be derived from processes within the plant, or may be obtained from off-site. For example, where the feed gas is separated by pressure swing adsorption, the PSA system may produce two separate streams of sour gas (of, for example, different composition), with one of said streams being divided into two parts, one of which is sent to the H₂S removal system and the other of which bypasses said system (as described above), and the other of said streams being processed, in its entirety, in the H₂S removal system (alongside said part of said first mentioned stream). Where the two streams of sour gas are of different composition (as may be the case where, for example, one is formed from gas obtained during the blowdown step of the PSA process and the other is formed from gas obtained during the purge step), it may in particular be preferable to process all of the stream of higher H₂S content (e.g. formed from the blowdown step) in the H₂S removal system, and divide the stream of lower H₂S content (e.g. formed from the purge step) into one part for processing in the H₂S removal system and another part for bypassing said system.

Apparatus of the present invention are suitable for carrying out the above described method. The apparatus comprises:

a pressure swing adsorption (PSA) system for separating the feed gas to form a stream of H₂-enriched product gas and a stream of sour gas, the sour gas comprising CO₂, H₂S and H₂ but being depleted in H₂ and enriched in H₂S and CO₂ relative to the feed gas;

an H₂S removal system for processing a part of the sour gas to form one or more streams of sweetened gas, depleted in H₂S and enriched in CO₂ relative to the feed gas;

conduit means for transferring a part of said sour gas into the H₂S removal system and bypassing the H₂S removal system with another part of said sour gas;

a valve system for adjustably controlling the division of said sour gas between being sent to the H₂S removal system and bypassing said system; and

conduit means for withdrawing one or more streams of sweetened gas from the H₂S removal system and combining said stream(s) with the sour gas bypassing the H₂S removal system to form H₂S-lean, CO₂ product gas.

The apparatus may further comprise a separation system for receiving the H₂S-lean, CO₂ product gas and separating said gas to form an H₂S-lean, H₂-lean, CO₂ product and a gas comprising H₂ (preferably, a second H₂-enriched gas).

In one embodiment:

the H₂S removal system comprises (i) a combustion system, for combusting sour gas in the presence of O₂ to produce heat and a combustion effluent depleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a system for converting H₂S to elemental sulfur via reaction with SO₂, and (iii) conduit means for transferring at least a portion of the combustion effluent from the combustion system to the H₂S to elemental sulfur conversion system to provide SO₂ for reaction with H₂S;

the conduit means for transferring a part of the sour gas into the H₂S removal system transfer a stream of sour gas into the combustion system and a stream of sour gas into the H₂S to elemental sulfur conversion system; and

the conduit means for withdrawing one or more streams of sweetened gas from the H₂S removal system withdraw a stream of sweetened gas from the H₂S to elemental sulfur conversion system and, optionally, a stream of sweetened gas from the combustion system formed from a portion of the combustion effluent.

In another embodiment:

the H₂S removal system comprises (i) a combustion system, for combusting sour gas in the presence of O₂ to produce heat and a combustion effluent depleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a system for receiving and separating the combustion effluent to form an SO₂-enriched stream and an SO₂-depleted stream (iii) a system for converting H₂S to elemental sulfur via reaction with SO₂, and (iv) conduit means for transferring the SO₂-enriched stream from the system for separating the combustion effluent to the H₂S to elemental sulfur conversion system to provide SO₂ for reaction with H₂S;

the conduit means for transferring a part of the sour gas into the H₂S removal system transfer a stream of sour gas into the combustion system and a stream of sour gas into the H₂S to elemental sulfur conversion system; and

the conduit means for withdrawing one or more streams of sweetened gas from the H₂S removal system withdraw a stream of sweetened gas from the H₂S to elemental sulfur conversion system and, optionally, a stream of sweetened gas from the system for separating the combustion effluent formed from the SO₂-depleted stream.

In another embodiment:

the H₂S removal system comprises (i) a combustion system, for combusting sour gas in the presence of O₂ to produce heat and a combustion effluent depleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a system for receiving combustion effluent from the combustion system, converting SO_(x) in said effluent to sulfuric acid and/or sulfurous acid, and separating said acid from the effluent to form an SO_(x)-depleted combustion effluent, (iii) a system for converting H₂S to elemental sulfur via reaction with sulfuric and/or sulfurous acid, and (iv) conduit means for transferring sulfuric and/or sulfurous acid from the SO_(x) to acid conversion system to the H₂S to elemental sulfur conversion system to provide sulfuric and/or sulfurous acid for reaction with H₂S;

the conduit means for transferring a part of the sour gas into the H₂S removal system transfer a stream of sour gas into the combustion system and a stream of sour gas into the H₂S to elemental sulfur conversion system; and

the conduit means for withdrawing one or more streams of sweetened gas from the H₂S removal system withdraw a stream of sweetened gas from the H₂S to elemental sulfur conversion system and, optionally, a stream of sweetened gas from the SO_(x) to sulfuric and/or sulfurous acid conversion system formed from the SO_(x)-depleted effluent.

The system for converting SO_(x) to sulfuric and/or sulfurous acid may, for example, comprise a cooling system for cooling the combustion effluent to condense out water and convert SO₃ to sulfuric acid, a compressor for elevating the pressure of the cooled combustion effluent, and a counter current gas/liquid contact device for washing the cooled combustion effluent with water at elevated pressure(s), in the presence of O₂ and optionally NO_(x), for a sufficient time to convert SO₂ to sulfurous acid and/or SO₂ to sulfuric acid and NO_(x) to nitric acid.

Further preferred features and embodiments of the apparatus according to the invention will be apparent from the foregoing description of preferred features and embodiments of the method of the invention.

Aspects of the invention include:

#1. Apparatus for treating a feed gas, comprising CO₂, H₂S and H₂, to produce an H₂-enriched product gas and an H₂S-lean, CO₂ product gas, the apparatus comprising:

a pressure swing adsorption (PSA) system for separating the feed gas to form a stream of H₂-enriched product gas and a stream of sour gas, the sour gas comprising CO₂, H₂S and H₂ but being depleted in H₂ and enriched in H₂S and CO₂ relative to the feed gas;

an H₂S removal system for processing a part of the sour gas to form one or more streams of sweetened gas, depleted in H₂S and enriched in CO₂ relative to the feed gas;

conduit means for transferring a part of said sour gas into the H₂S removal system and bypassing the H₂S removal system with another part of said sour gas;

a valve system for adjustably controlling the division of said sour gas between being sent to the H₂S removal system and bypassing said system; and

conduit means for withdrawing one or more streams of sweetened gas from the H₂S removal system and combining said stream(s) with the sour gas bypassing the H₂S removal system to form H₂S-lean, CO₂ product gas.

-   #2. An apparatus according to #1, wherein the apparatus further     comprises a separation system for receiving the H₂S-lean, CO₂     product gas and separating said gas to form an H₂S-lean, H₂-lean,     CO₂ product and a second H₂-enriched gas. -   #3. An apparatus according to #1 or #2, wherein:

the H₂S removal system comprises (i) a combustion system, for combusting sour gas in the presence of O₂ to produce heat and a combustion effluent depleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a system for converting H₂S to elemental sulfur via reaction with SO₂, and (iii) conduit means for transferring at least a portion of the combustion effluent from the combustion system to the H₂S to elemental sulfur conversion system to provide SO₂ for reaction with H₂S;

the conduit means for transferring a part of the sour gas into the H₂S removal system transfer a stream of sour gas into the combustion system and a stream of sour gas into the H₂S to elemental sulfur conversion system; and

the conduit means for withdrawing one or more streams of sweetened gas from the H₂S removal system withdraw a stream of sweetened gas from the H₂S to elemental sulfur conversion system and, optionally, a stream of sweetened gas from the combustion system formed from a portion of the combustion effluent.

-   #4. An apparatus according to #1 or #2, wherein:

the H₂S removal system comprises (i) a combustion system, for combusting sour gas in the presence of O₂ to produce heat and a combustion effluent depleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a system for receiving and separating the combustion effluent to form an SO₂-enriched stream and an SO₂-depleted stream (iii) a system for converting H₂S to elemental sulfur via reaction with SO₂, and (iv) conduit means for transferring the SO₂-enriched stream from the system for separating the combustion effluent to the H₂S to elemental sulfur conversion system to provide SO₂ for reaction with H₂S;

the conduit means for transferring a part of the sour gas into the H₂S removal system transfer a stream of sour gas into the combustion system and a stream of sour gas into the H₂S to elemental sulfur conversion system; and

the conduit means for withdrawing one or more streams of sweetened gas from the H₂S removal system withdraw a stream of sweetened gas from the H₂S to elemental sulfur conversion system and, optionally, a stream of sweetened gas from the system for separating the combustion effluent formed from the SO₂-depleted stream.

-   #5. An apparatus according to #1 or #2, wherein:

the H₂S removal system comprises (i) a combustion system, for combusting sour gas in the presence of O₂ to produce heat and a combustion effluent depleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a system for receiving combustion effluent from the combustion system, converting SO_(x) in said effluent to sulfuric and/or sulfurous acid, and separating said acid from the effluent to form a SO_(x)-depleted combustion effluent, (iii) a system for converting H₂S to elemental sulfur via reaction with sulfuric and/or sulfurous acid, and (iv) conduit means for transferring sulfuric acid and/or sulfurous acid from the SO_(x) to acid conversion system to the H₂S to elemental sulfur conversion system to provide sulfuric and/or sulfurous acid for reaction with H₂S;

the conduit means for transferring a part of the sour gas into the H₂S removal system transfer a stream of sour gas into the combustion system and a stream of sour gas into the H₂S to elemental sulfur conversion system; and

the conduit means for withdrawing one or more streams of sweetened gas from the H₂S removal system withdraw a stream of sweetened gas from the H₂S to elemental sulfur conversion system and, optionally, a stream of sweetened gas from the SO_(x) to sulfuric and/or sulfurous acid conversion system formed from the SOx-depleted combustion effluent.

-   #6. An apparatus according to #5, wherein the system for converting     SO_(x) to sulfuric and/or sulfurous acid comprises a cooling system     for cooling the combustion effluent to condense out water and     convert SO₃ to sulfuric acid, a compressor for elevating the     pressure of the cooled combustion effluent, and a counter current     gas/liquid contact device for washing the cooled combustion effluent     with water at elevated pressure(s), in the presence of O₂ and     optionally NO_(x), for a sufficient time to convert SO₂ to sulfurous     acid and/or SO₂ to sulfuric acid and NO_(x) to nitric acid.

Solely by way of example, certain embodiments of the invention will now be described with reference to the accompanying drawings.

Referring to FIG. 1, sour syngas stream 10, comprising H₂, CO, CO₂ and H₂S, is fed into PSA system 12, which separates the sour syngas by pressure swing adsorption into a high pressure stream, 14, of H₂-enriched product gas and a low pressure stream, 16, of sour gas. The sour gas also comprises H₂, CO, CO₂ and H₂S, but is enriched in CO₂ and H₂S and depleted in H₂ relative to the sour syngas. The H₂-enriched product stream 14 may be expanded in optional expander 32, prior to, for example, being sent as fuel to a gas turbine to generate power (as, for example, where the H₂-enriched product comprises gas turbine fuel grade purity H₂) or exported for chemicals or refining applications (as, for example, where H₂-enriched gas comprises high purity, e.g. 99.99 mole % or higher, H₂ product or a high purity syngas comprising a desired H₂/CO ratio).

Sour gas stream 16 is divided into two further streams, 18 and 24 (which, therefore, remain of the same composition as stream 16). The division of the sour gas between streams 18 and 24 is adjustable, as will be described below in further detail.

Sour gas stream 18 is fed into H₂S removal system 20, which processes the stream to selectively remove all or substantially all the H₂S therefrom, thereby forming stream 22 of sweetened gas which is devoid or almost devoid of H₂S. The H₂S removal system may employ any suitable means of H₂S removal, including (but not limited to) adsorption, conversion to elemental sulfur, and/or combustion. The operation of two exemplary H₂S removal systems will be described in further detail below, with reference to FIGS. 2 and 3. Sour gas stream 24 bypasses the H₂S removal system and is combined with sweetened gas stream 22 to form a H₂S-lean, CO₂ product gas. In the depicted embodiment streams 22 and 24 are combined to form stream 26 of H₂S-lean, CO₂ product gas, which stream is then compressed in compressor 28 prior to, optionally, being fed to a further separation system. Equally, however, streams 22 and 24 could be combined within compressor 28 to form the H₂S-lean, CO₂ product gas, or could be separately compressed and combined subsequently to form the H₂S-lean, CO₂ product gas.

The division of the sour gas between streams 18 and 24 is adjustable, so that it can be changed responsive to changes in the H₂S content of the sour gas. In this way, should the H₂S content of stream 16 rise, for example due to the H₂S content of sour syngas stream 10 rising as a result of a change in gasifier/reformer feedstock, the flow rate of stream 18 can be increased and the flow rate of stream 24 decreased in order to keep the H₂S content of the H₂S-lean, CO₂ product gas at or below a desired maximum content as dictated by the emissions and/or CO₂ product specifications that the process is to meet. Likewise, should the H₂S content of stream 16 drop, the flow rate of stream 18 may be reduced and flow rate of stream 24 increased, up to a level at which the desired maximum H₂S content of the H₂S-lean, CO₂ product gas is still not exceeded, thereby conserving resources and/or reducing costs associated with the H₂S removal process.

As noted above, stream 26 of H₂S-lean, CO₂ product gas may, optionally, be compressed in compressor 28 and then fed to a further separation system. In the embodiment depicted in FIG. 1, the further separation system is a membrane separation system 30 comprising one or more membranes that are permeable to H₂ but relatively impermeable to CO₂, but other types of system, such as for example a partial condensation system, could equally be used. The compressed H₂S-lean, CO₂ product gas is separated in the membrane separation system 30 into a stream 34 of H₂-enriched gas, obtained at lower pressure from the permeate side of the membrane(s), and a stream 36 of H₂S-lean, H₂-lean CO₂ product gas obtained from the upstream side of the membrane(s). Optionally, an N₂ ‘sweep’ stream 38 is also used to increase the driving force for separation, allowing stream 34 of second H₂-enriched gas leaving the membrane separation system to be obtained at a higher pressure with the same membrane surface area. The second stream 34 of H₂-enriched gas may be blended with stream 14 of H₂-enriched product gas, recycled to PSA system 10 (for example by being added to sour syngas stream 10 or by being used in a rinse or repressurisation step of the PSA cycle), or used in another process. The H₂S-lean, H₂-lean CO₂ product stream may be compressed in compressor 40 prior to being piped for geological storage or EOR.

In the embodiment depicted in FIG. 1, sour syngas stream 10 may for example comprise about 57% H₂, 3% CO, 40% CO₂, and 100 ppm H₂S (all percentages being mole %) and be introduced into PSA system at 1.2 to 6 MPa (12 at 60 bar) absolute. The H₂-enriched product stream 14 may comprise 95% H₂ and 5% CO and be obtained at the same or about the same pressure as the sour syngas feed to the PSA system (i.e. subject to any unavoidable pressure drop associated with flow through the adsorbent packed bed), and the sour gas streams 16 may comprise about 93% CO₂, 6.6% H₂, 0.4% CO, and 233 ppm H₂S and be obtained at 1 bar absolute. The stream of sweetened gas produced by the H₂S removal system (for example comprising a catalytic system for converting H₂S to elemental sulfur, e.g. LO-CAT, followed by a ZnO bed for final polishing) may comprise about 6.6% H₂, 0.4% CO, 93% CO₂, 2 ppm H₂S. The H₂S-lean, CO₂ product stream 26 may comprise about 6.6% H₂, 0.4% CO, 93% CO₂ and 94 ppm H₂S. The second H₂-enriched gas may comprise 100% H₂ or (if an N₂ sweep is used) H₂/N₂. The H₂S-lean, H₂-lean CO₂ product stream 36 may comprise about 96% CO₂, 4% CO and 98 ppm H₂S, and may be compressed to a pressure of 12 MPa (120 bar) absolute.

Referring to FIG. 2, in one exemplary embodiment the H₂S removal system 20 comprises both an oxy-fuel combustion system 50 and an H₂S to elemental sulfur conversion system 52 comprising a catalyst that catalyses the conversion of H₂S to elemental sulfur via reaction with SO₂.

In the depicted embodiment, sour gas stream 18 is divided into streams 54 and 56 but, equally, one or both of streams 54 and 56 could be divided from stream 16 at the same time as or before stream 24. Stream 54 is introduced into oxy-fuel combustion system 50 and combusted in the presence of oxygen, provided by high purity oxygen stream 58, so as to combust all or substantially all of the H₂, CO and H₂S present in the stream, thereby producing a combustion effluent 62 comprising CO₂, SO_(x) and H₂O. Optionally, additional fuel may also be supplied to and combusted in the oxy-fuel combustion system 50, as indicated by stream 60. The combustion effluent 62 is then passed to heat exchanger 64 to recover heat therefrom via indirect heat exchange.

Stream 56 of sour gas is introduced into the H₂S to elemental sulfur conversion system 52 where all or substantially all of the H₂S in the stream is reacted with SO₂ over the catalyst to produce elemental sulfur and H₂O (via the reaction 2H₂S+SO₂→⅜S₈+2H₂O) and form stream 22 of sweetened gas. The sulfur is removed as stream 68 via a sulfur handling process within the conversion system. The SO₂ required for this reaction is supplied by feeding at least a portion 66 of the combustion effluent 62 into the conversion system, the amount of combustion effluent fed into the conversion system preferably being such as to provide an amount of SO₂ sufficient for, but not significantly in excess of, the stoichiometric amount required for reaction with H₂S. The heat required for optimal conversion of H₂S to sulfur may be supplied by the heat recovered from the combustion effluent in heat exchanger 64. Alternatively or additionally, the heat recovered from the combustion effluent in heat exchanger 64 may be put to other uses, such as for example heating stream 14 of H₂-enriched product gas prior to said stream being expanded in optional expander 32.

Heat exchanger 64, although depicted as a single unit, could comprise one or more heat exchangers in series or parallel. The recovery of heat from stream 62 in heat exchanger 64 could, for example be via indirect heat transfer with any or all of streams 54, 58, 60, 56, and 14 by passing said stream(s) through heat exchanger 64 also. Alternatively, a separate a heat transfer fluid (e.g. steam), could be used that is circulated through heat exchanger 64 and separate heat exchangers (not shown) associated with any or all of streams 54, 58, 60, 56, and 14 to achieve indirect heat transfer with these streams. A separate heat transfer fluid (not shown) heated by stream 62 in heat exchanger 64 could also, for example, be used to heat the catalyst beds of conversion system 52.

The stream 22 of sweetened gas obtained from conversion system 52 is then combined with stream 24 of sour gas to form the H₂S-lean, CO₂ product, as described above with reference to FIG. 1. Water present in the sweetened gas can be removed prior to or after combining the stream with stream 24 of sour gas. For example, water may be removed during compression of the stream(s) in compressor 28. A further portion of the combustion effluent 62 may optionally also be taken as a second, SO_(x) containing, stream 70 of sweetened gas. This second stream of sweetened gas may be combined with the stream of sweetened gas from conversion system 52 as shown in FIG. 2, or the two streams of sweetened gas may be separately added to stream 24 of sour gas to form the H₂S-lean, CO₂ product. Where, in particular, a second stream 70 of sweetened gas is formed from a portion of the combustion effluent, it is preferable that both the division of sour gas between the streams, 54 and 56, fed to the oxy-combustion and conversion systems, 50 and 52, and the division of the combustion effluent 62 between being sent to the conversion system 52 and being taken as the second stream 70 of sweetened gas, are adjustable so that both the desired reaction stoichiometry within the conversion system 52 and desired limits on SO_(x) content of the H₂S-lean, CO₂ product gas can be maintained in the event of a change in the H₂S content of the sour gas streams 16, 18, 24, 54 and 56.

In the arrangement depicted in FIG. 2, sour gas streams 18, 54 and 56 may for example comprise about 93% CO₂, 6.6% H₂, 0.4% CO, and 233 ppm H₂S. Combustion effluent 62 may comprise about 99% CO₂ and 235 ppm SO_(x). Stream 22 of sweetened gas may comprise about 96% CO₂ and 4% H₂/CO₂ (a second stream 70 of sweetened gas not, in this example, being formed from the combustion effluent). The H₂S-lean, CO₂ product stream 26 may then comprise about 5.2% H₂, 0.8% CO, 94% CO₂ and 71 ppm H₂S, and the H₂S-lean, H₂-lean CO₂ product stream 36 may comprise about 99% CO₂, 1% CO and 76 ppm H₂S. All the above figures are calculated on a dry basis.

Referring to FIG. 3, an alternative exemplary embodiment of the H₂S removal system is shown, the same reference numerals being used in FIG. 3 as in FIG. 2 to denote common features. The removal system 20 in this embodiment comprises both an oxy-fuel combustion system 50 and an H₂S to elemental sulfur conversion system 82 in which H₂S is converted to elemental sulfur via reaction with sulfuric acid (H₂SO₄) and/or sulfurous acid (H₂SO₃). Streams 54 and 56 of sour gas are, again, fed to the combustion system 50 and conversion system 82, respectively, the combustion system 50 combusting all or substantially all of the H₂, CO and H₂S in sour gas stream 54 to form combustion effluent 62 comprising CO₂, SO_(x) and H₂O, and the conversion system 82 converting all or substantially all of the H₂S in the sour gas stream 56 to elemental sulfur to provide stream 22 of sweetened gas and stream 68 of sulfur. Combustion effluent 62 is, again, passed through heat exchanger 64 to recover heat therefrom via indirect heat exchange.

In this arrangement, however, the combustion effluent 62 exiting heat exchanger 64 is introduced into SO_(x) to acid conversion system 80 where it is cooled (in a further heat exchanger), compressed and maintained at elevated pressure, in the presence of O₂, water and optionally NO_(x), to convert all or substantially all of the SO_(x) in the combustion effluent to H₂SO₄ and/or H₂SO₃, thereby forming a further stream 84 of sweetened gas and a stream 86 of aqueous H₂SO₄ and/or H₂SO₃. At least a portion of this acid (optionally, after evaporation of some of the water to obtain a more concentrated solution of acid) is then introduced into the H₂S to elemental sulfur conversion system 82, the amount of acid fed into the conversion system preferably being at least sufficient to provide the stoichiometric amount H₂SO₄ and/or H₂SO₃ required for conversion of all of the H₂S in sour gas stream 56, which proceeds according to the reactions 3H₂S(g)+H₂SO₄(I)→4S+4H₂O(I) and 2H₂S(g)+H₂SO₃(I)→3S+3H₂O(I).

The heat recovered from the combustion effluent in heat exchanger 64 may again be supplied to the H₂S to elemental sulfur conversion system 82 as required for optimal conversion of H₂S, and/or put to other uses. The streams of sweetened gas 84 and 22 obtained from the SO_(x) to acid conversion system 80 and H₂S to elemental sulfur conversion system 82 may be combined, as shown in FIG. 3, prior to being combined with sour gas stream 24 to form the H₂S-lean, CO₂ product, or the two streams of sweetened gas may be separately added to stream 24 of sour gas.

It will be appreciated that the invention is not restricted to the details described above with reference to the preferred embodiments but that numerous modifications and variations can be made without departing form the spirit or scope of the invention as defined in the following claims. 

The invention claimed is:
 1. Apparatus for treating a feed gas, comprising CO₂, H₂S and H₂, to produce an H₂-enriched product gas and an H₂S-lean, CO₂ product gas, the apparatus comprising: a pressure swing adsorption (PSA) system for separating the feed gas to form a stream of H₂-enriched product gas and a stream of sour gas, the sour gas comprising CO₂, H₂S and H₂ but being depleted in H₂ and enriched in H₂S and CO₂ relative to the feed gas; an H₂S removal system for processing a part of the sour gas to form one or more streams of sweetened gas, depleted in H₂S and enriched in CO₂ relative to the feed gas; conduit means for transferring a part of said sour gas into the H₂S removal system and bypassing the H₂S removal system with another part of said sour gas; a valve system for adjustably controlling the division of said sour gas between being sent to the H₂S removal system and bypassing said system; and conduit means for withdrawing one or more streams of sweetened gas from the H₂S removal system, and combining said stream(s) with the sour gas bypassing the H₂S removal system to form H₂S-lean, CO₂ product gas.
 2. An apparatus according to claim 1, wherein the apparatus further comprises a separation system for receiving the H₂S-lean, CO₂ product gas and separating said gas to form an H₂S-lean, H₂-lean, CO₂ product and a second H₂-enriched gas.
 3. An apparatus according to claim 1, wherein: the H₂S removal system comprises (i) a combustion system, for combusting sour gas in the presence of O₂ to produce heat and a combustion effluent depleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a system for converting H₂S to elemental sulfur via reaction with SO₂, and (iii) conduit means for transferring at least a portion of the combustion effluent from the combustion system to the H₂S to elemental sulfur conversion system to provide SO₂ for reaction with H₂S; the conduit means for transferring a part of the sour gas into the H₂S removal system transfer a stream of sour gas into the combustion system and a stream of sour gas into the H₂S to elemental sulfur conversion system; and the conduit means for withdrawing one or more streams of sweetened gas from the H₂S removal system withdraw a stream of sweetened gas from the H₂S to elemental sulfur conversion system and, optionally, a stream of sweetened gas from the combustion system formed from a portion of the combustion effluent.
 4. An apparatus according to claim 1, wherein: the H₂S removal system comprises (i) a combustion system, for combusting sour gas in the presence of O₂ to produce heat and a combustion effluent depleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a system for receiving and separating the combustion effluent to form an SO₂-enriched stream and an SO₂-depleted stream (iii) a system for converting H₂S to elemental sulfur via reaction with SO₂, and (iv) conduit means for transferring the SO₂-enriched stream from the system for separating the combustion effluent to the H₂S to elemental sulfur conversion system to provide SO₂ for reaction with H₂S; the conduit means for transferring a part of the sour gas into the H₂S removal system transfer a stream of sour gas into the combustion system and a stream of sour gas into the H₂S to elemental sulfur conversion system; and the conduit means for withdrawing one or more streams of sweetened gas from the H₂S removal system withdraw a stream of sweetened gas from the H₂S to elemental sulfur conversion system and, optionally, a stream of sweetened gas from the system for separating the combustion effluent formed from the SO₂-depleted stream.
 5. An apparatus according to claim 1, wherein: the H₂S removal system comprises (i) a combustion system, for combusting sour gas in the presence of O₂ to produce heat and a combustion effluent depleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a system for receiving combustion effluent from the combustion system, converting SO_(x) in said effluent to sulfuric and/or sulfurous acid, and separating said acid from the effluent to form an SO_(x)-depleted combustion effluent, (iii) a system for converting H₂S to elemental sulfur via reaction with sulfuric and/or sulfurous acid, and (iv) conduit means for transferring sulfuric and/or sulfurous acid from the SO_(x) to acid conversion system to the H₂S to elemental sulfur conversion system to provide sulfuric and/or sulfurous acid for reaction with H₂S; the conduit means for transferring a part of the sour gas into the H₂S removal system transfer a stream of sour gas into the combustion system and a stream of sour gas into the H₂S to elemental sulfur conversion system; and the conduit means for withdrawing one or more streams of sweetened gas from the H₂S removal system withdraw a stream of sweetened gas from the H₂S to elemental sulfur conversion system and, optionally, a stream of sweetened gas from the SO_(x) to sulfuric and/or sulfurous acid conversion system formed from the SO_(x)-depleted effluent.
 6. An apparatus according to claim 5, wherein the system for converting SO_(x) to sulfuric and/or sulfurous acid comprises a cooling system for cooling the combustion effluent to condense out water and convert SO₃ to sulfuric acid, a compressor for elevating the pressure of the cooled combustion effluent, and a counter current gas/liquid contact device for washing the cooled combustion effluent with water at elevated pressure(s), in the presence of O₂ and optionally NO_(x), for a sufficient time to convert SO₂ to sulfurous acid and/or SO₂ to sulfuric acid and NO_(x) to nitric acid. 